GAS HYDRATE ACCUMULATION TYPES AND THEIR APPLICATION TO NUMERICAL SIMULATION

Ray Boswell* 1U.S. Department of Energy, National Energy Technology Laboratory

Morgantown, WV USA

George Moridis, Matthew Reagan

Lawrence Berkeley National Laboratory, Berkeley, CA USA

Timothy S. Collett

U.S. Geological Survey, Denver, CO USA

ABSTRACT Recent field programs in Alaska and the Gulf of Mexico provide new insights into the geometry and architecture of gas hydrate accumulations. This report discusses an expanded system of classification that accommodates the varied nature of these deposits with the goal of supporting the numerical simulation of gas hydrate resource, geohazard, and environmental issues across the range of gas hydrate occurrence modes. We recognize “Types” and various sub-types that describe fundamentally-different accumulations via reference to the nature of the host sediments. Within these types, “classes” from the system of Moridis and Collett (2002) describe well specific reservoir settings that primarily reference the nature of the bounding lithologies. Each class includes sub-classes that describe the bounding units as either confined (i.e. Class 2c) or unconfined (i.e., Class 2u). We designate those accumulations that occur in unconsolidated, coarser-grained sediments as Type C. Type C includes two end-member primary sub-types; CTB are marked by thinly-interbedded sands and shales, with CMB being thicker, massively-bedded units. Accumulations within unconsolidated, fine-grained, low-permeability sediments are named Type F, and occur in two primary Types. Type FPF represents accumulations in which gas hydrate occurs in primarily pore-filling mode, typically at very low saturations. Type FGD deposits are those in which the gas hydrate is primarily in the form of grain-displacing veins, nodules, and fracture-fills. Two sub-types within Type FGD relate to the geometry of the unit; with Type FGD-Ch (“chimneys”) being discordant with local stratigraphy and commonly exhibiting locally high concentrations, and Type FGH-SB (“stratal-bound”) occurring within specific stratigraphic units, often at low to moderate saturations. Type M (“mounds”) refer to massive gas hydrate deposits associated with cold seeps that occur in very shallow sediments or outcrop on the sea floor. Finally, Type R includes accumulations within rocks. We illustrate the application of this system to various known gas hydrate occurrences and review the status of numerical simulation conducted to date relative to each. Keywords: gas hydrates, reservoir modeling,

Proceedings of the 7th International Conference on Gas Hydrates (ICGH 2011), Edinburgh, Scotland, United Kingdom, July 17-21, 2011.

NOMENCLATURE Sgh Gas Hydrate Saturation [% of pore space] Sw Water Saturation [% pore space] INTRODUCTION Gas hydrates and gas-hydrate-bearing sediments, given their abundance and variety in nature, present a range of implications for numerous science and technology issues [1]. Primary among these are the response to 1) a range of potential well-based production methods [2], and 2) potential response to changes in the natural environment at a variety of spatial and temporal scales [3,4]. The effort to better understand, predict, and manage these varied phenomena is primarily focused on the numerical depiction and simulation of natural gas hydrate deposits. The continuing maturation of both the various numerical codes as well as the improved understanding of natural occurrences provided by recent drilling programs are yielding increasingly sophisticated and diverse numerical simulations [5,6]. To date, numerical simulation of gas hydrate occurrences has focused primarily on their potential as an energy resource, and as a result, the majority of numerical simulations have focused on depictions of those coarse-grained accumulations that are most amenable to known production technologies [5]. To support these works, a classification system was devised [7] that assigns prospective gas hydrate accumulations to one of four classes, with a number of sub-varieties. These classes primarily reference the geometry of the unit with particular focus on the nature of upper and lower reservoir boundaries. In Classes 1, 2, and 3, there is an implicit assumption that the reservoir is a distinct reservoir-quality (high intrinsic permeability) stratigraphic unit that is bound by sealing lithologies of significantly lower intrinsic permeability. In addition, gas hydrate occurrence within the units is assumed to be pore-filling. The overall nature of the four currently recognized gas hydrate reservoir Classes is as follows (Figure 1): Class 1 accumulations are those that occur at the base of the gas hydrate stability zone (GHSZ) in which a well-defined gas-hydrate-bearing layer (HBL) is in full communication with a subjacent unit of very similar petrophysical properties that contains free gas. Such reservoirs can alternatively

be viewed as free gas reservoirs with an up-dip or overlying gas-hydrate trap. Class 1G represents those settings where free gas co-exists in the hydrate-bearing zone, whereas Class 1W are those in which the reservoir pore space is primarily gas hydrate and water.

Figure 1: Gas hydrate reservoir classes (after [7]).

Dashed red line is BGHS. Reservoir quality sediments are shown with varying pore fill: gas hydrate (yellow), water (blue) and gas (green).

Brown indicates fine-grained units of significantly lower reservoir-quality.

Class 2 deposits are those in which the reservoir-quality section consists of a gas hydrate-saturated interval overlying a hydrate-free zone containing free water. This setting may occur at the base of the GHSZ, or well within the GHSZ when gas charge is limited. Class 3 includes those reservoirs in which the reservoir-quality unit is fully saturated with gas hydrate, allowing no potential communication with water- or free-gas bearing reservoir-quality units. Class 4 represents those accumulations in which Sgh is low (commonly less than 5%, but locally up to perhaps 20%) and the vertical extent of the occurrence is not controlled by any significant changes in reservoir quality (i.e., there are no effective potential lateral or vertical seals [8]). Class 4 settings would be typically associated with non-reservoir quality (low intrinsic permeability) fine-grained marine sediments in which the gas hydrate occurs primarily at the base of the GHSZ. Although this classification system is currently widely used to support gas hydrate reservoir production modeling, several recent developments in gas hydrate R&D suggest that an expansion of this system is in order.

Figure 2. Map-view schematic depiction of the WR313 ‘blue” (Type C) gas hydrate reservoir. Cartoon cross-sections at bottom show inferred Class 1 geometry along the BGHS to the north, Class 2 geometry along the BGHS to the south,

and Class 3 geometry as traced up structural dip to the southeast.

First, while prior numerical simulation has focused on induced dissociation for commercial gas extraction, the initial numerical simulations of the behavior of gas hydrate bearing sediments under scenarios of natural environmental change are now appearing [9]. Such simulations are meaningful and necessary throughout the range of gas hydrate occurrence modes, not just those that have the best energy production potential, and therefore are not all well-accommodated within the existing Classes. Second, recent drilling results, particularly offshore Malaysia [10], the east coast of India [11], Korea [12], and in the Gulf of Mexico [13] have indicated the occurrence of a new form of gas hydrate deposit. In these regions, gas hydrate has been encountered at a range of moderate saturations (Sgh from ~5% up to ~40%) in the form of grain-displacing veins, nodules, and fracture-fills within fine-grained sediments. Given

their apparent wide-spread occurrence and elevated gas hydrate content, numerical simulation of such features, either for with respect to geohazard appraisal, climate change response, or for potential energy production under yet-to-be-articulated production methods, is likely. Third, recent drilling results are revealing new insights into the varied architecture of natural accumulations. Most importantly, individual contiguous reservoirs are observed to possess the characteristics of multiple classes at different locations within their extent. For example, the gas hydrate deposit in the Walker Ridge area of the Gulf of Mexico [14] consists of reservoir sands that traverse the base of gas hydrate stability. Up-dip of the BGHS, the reservoir is fully saturated with gas hydrate and bound above and below by muds (Class 3). However, any wells located proximal to the BGHS would have Class 1 or Class 2 settings. This up-dip transition from Class 1 to Class 3 settings may be very common in the marine environment where dipping sands traverse the BGHS. In this particular location, local variations in thermal gradients (resulting in the BGHS not conforming to structure whereas the buoyancy-driven gas-water contacts do) result in a lateral change along the BGHS from Class 1 to Class 2 configuration (Figure 2). To accommodate the data now arriving from field studies, and to address the wide range of issues related to gas hydrate, future numerical simulation will address increasingly variable and complex settings. Perhaps most notably, accumulations beyond those occurring in sands will be increasingly studied, both to enable the further evaluation of fine-grained systems for potential natural gas production as well as to enable further analysis of the response of gas hydrate deposits to global environmental changes. The following section provides summary reviews of specific field examples of each reservoir type and location-specific reservoir configuration, and summarizes the results of numerical simulations as available. GAS HYDRATE RESERVOIR TYPES Recent data acquired in the field confirms that the primary element controlling the nature and behavior of gas hydrate is the nature of the enclosing media [15]. One feature characteristic of most gas hydrate accumulations, and probably all marine gas hydrates, is the presence of

unconsolidated or poorly consolidated host sediment. Within these settings, we recognize two fundamental end-member types; Type C for relatively coarse-grained settings and Type F or relatively fine-grained settings. For those occurrences that are not sediment-hosted, (primarily the massive mounds observed to occur in association with sea-floor cold seeps), we use Type M. In addition, there are a few examples of gas hydrate occurrence within competent rocks (all in permafrost-associated settings) and these we assign to Type R. Type C Reservoirs Type C reservoirs are those in which the host sediment has high intrinsic (in the absence of gas hydrate) permeability, a feature that is commonly associated with well-sorted sediments of relatively coarse grain size. Type C has the primary characteristic of enabling Sgh to characteristically reach values of 50% and locally as high as 85% or more and is the most favorable occurrence type for potential energy production [16]. In permafrost-associated settings, it is likely that Type C represents a high proportion of total gas hydrate occurrence. However, in the marine setting, Type C reservoirs are generally presumed to represent a much smaller share of total gas hydrate in-place resources, although recent studies in both the Nankai Trough [17] and in the Gulf of Mexico [18] suggest that they may be much more prevalent, at least regionally, than commonly assumed [19]. At their extremes, the distinction between Type C and the Type F accumulations is significant. The primary control of importance is intrinsic permeability, which although closely linked to grain size, is also influenced by porosity, grain texture, sediment sorting, and other factors. However, these Types represent end-members of a continuum distribution. In well-sorted sediments, high intrinsic permeability is maintained in sediments well into the silt size range (Figure 3). Therefore, the common distinction between “coarse-grained” and “fine-grained” reservoirs is not necessarily at the nominal sand/silt cut-off (62 microns), but somewhere within the middle-to-lower silt size range. Further understanding of the nature of this transition will be important, as it can be expected that many deepwater reservoirs will consist of very fine sands and silts and therefore may fall within this grey area.

Figure 3: In well-sorted sediments, high

permeability can extend well below the nominal sand/silt grain-size cut-off; from [20].

Heterogeneity is a key reservoir attribute that has a significant impact on the behaviour of naturally-occurring deposits. Vertical interlaying of units of different reservoir quality can have significant positive implications for production rate [6] by enabling much greater area of the dissociation front, as well as providing additional sources for heat transfer from non-gas-hydrate-bearing units to those undergoing endothermic cooling. Lateral heterogeneity can have mixed implications for production potential [21]. While all reservoirs are naturally-heterogeneous, we recognize two generalized end-members as follows. Type CTB deposits are those in which the gas-hydrate-bearing sands are thinly interbedded with muds. Individual layers are typically less than 1 m in thickness, but can occur in thick gross intervals with high sand-to-mud ratio. Examples of Type CTB include the various sand-rich deepwater turbiditic facies of the Nankai Trough [22] as well as the Green Canyon 955 [14] deposits. Type CMB includes more massively-bedded sands, such as the hydrate-bearing sands at Mallik or the “orange” sand in Walker Ridge 313 [14]. To segregate the coarse-grained reservoir classes in a manner most meaningful for well-specific reservoir simulation, the pre-existing gas hydrate reservoir classes [7] are recognized. These classes are used here not to refer to an entire reservoir, but to the specific setting present at any given (well) location within the accumulation. In addition, within each of the classes, we suggest an additional modifier to represent the nature of the bounding non-hydrate-bearing units based on whether the unit is interpreted to be unconfined

(Class 1u, 2u, or 3u) or confined (Class 1c, 2c, or 3c). Unconfined refers to those settings where lateral or vertical seals are not present or are ineffective hydraulic barriers. Lack of such barriers severely complicates the effort to depressurize by enabling reservoir communication with effectively infinitely-acting gas or water reservoirs. Confined settings are those in which lateral and vertical seals are present, restricting mobile fluids (either gas or water) to limited volumes, allowing depressurization to occur through the withdrawal of pore fluids. Class 1 well settings: To date, there are no clearly documented occurrences of Type C/Class 1 conditions in arctic Alaska or Canada, although they are likely to exist along the eastern margin of the Eileen gas hydrate trend [23]. Class 1 settings have been reported for Type R (consolidated host sediment) reservoirs in Russia, Alaska, and China, and are discussed further below. Similarly, the occurrence of Type C/Class 1 deposits has not yet been conclusively demonstrated in the marine environment. This seemingly lack of Class 1 geometries suggests that gas hydrate in coarse-grained sediments may not be a effective seal; however, recent drilling results in the Gulf of Mexico indicate that such settings may occur at select locations within the Green Canyon 955 (Q-location), and may also occur within multiple horizons at the Walker Ridge 313 area. In both cases, the occurrence of free gas in communication with overlying gas hydrate is indicated by seismic data (although degree of gas saturation is uncertain and may be low), with additional drilling indications of free gas at the GC955-Q site [24]. Preliminary modeling of the production potential of the WR313 reservoirs [25] has focused on the Class 3 settings located further up-dip within the deposit as shown in Figure 3 and discussed further below. Class 1 deposits may also be either confined or unconfined. In practicality, Class 1u would refer to settings in which the subjacent free gas reservoir being tapped was producing via water-drive. This condition would greatly limit the ability to depressurize the reservoir and would ultimately transition the deposit to the Class 2u case. Class 1c would apply when the subjacent gas-bearing zone was producing via depletion-drive. Therefore, similar to the case of Class 2

(discussed below), the unconfined condition results in inferior production, particularly with respect to the hydrate contribution. Among the varieties discussed in this report, numerical simulation has consistently shown Type C/Class 1c reservoirs as the most favorable setting for gas hydrate production [5]. However, these reservoirs may not be attractive sites for scientific production testing due to complexities in effectively evaluating the gas hydrate contribution to produced gas volumes. Class 2 well settings: Class 2 settings, in which gas hydrate overlies and effectively communicates with water-bearing units of similar reservoir quality, appear to be very common. The majority of locations within gas hydrate accumulations of the Nankai Trough appear to be Type CTB/Class 2 settings, although some locations also locally exhibit Class 3 geometries (Figure 4). Nankai Trough reservoirs consist primarily of thinly-bedded sand-rich turbidites that commonly traverse the BGHS with no free gas observed in the sands below the BGHS [26]. Information on the extent of these water-filled sands, and whether they might behave as either confined or unconfined, is not readily available, however production strategies have been designed to produce from within the hydrate-bearing layer to minimize the potential for communication with the water-bearing portions of the reservoir [27].

Figure 4: Gas hydrate-bearing turbidite sands in the Nankai Trough showing both Class 2 and Class 3 configurations. Modified from [26].

Initial estimates of production potential for Nankai Trough accumulations have focused on two drill locations: α-1 and β-1 [28]. The α-1 deposit consists of 110-meters of gently-dipping sand-rich

turbiditic lobe facies located approximately 100 m below the sea-floor in an area of complex faulting. The β-1 deposit includes 70 meters of more steeply-dipping turbiditic channel facies at roughly 170 meters below the seafloor. Numerical simulation of the response of these deposits to depressurization via vertical wells predicts a range of production rates from 6,400 m3/d for the α-1 location to 150,000 m3/d for the β-1 location [27]. A well-documented marine Type CMB/Class 2 reservoir occurs in Alaminos Canyon block 818, northern Gulf of Mexico [29]. The deposit occurs where a thick section of very fine-grained and volcaniclastic Oligocene Frio sand is uplifted such that a small (200-acre) area of the fold crest transects the BGHS. Log data confirms high Sgh above the BGHS and high Sw (with only trace amounts of gas) below. The water bearing section includes roughly 30 m of sand vertically at the fold crest as well as an inferred extensive occurrence along the steeply-dipping eastern limb of the fold. This down-dip water-bearing unit renders the deposit unconfined (Class 2u) and numerical simulations underscore the importance of this lack of confinement on production response. Numerical simulation of the unit as unconfined shows low production rates (maximum 1.5 million ft3/day with 30,000 barrels of water per day) due to strong water inflow from the down-dip and fully connected aquifer. In contrast, imposition of confined conditions increases productivity dramatically, to an average of ~60 million ft3/day before the deposit is depleted [29].

Figure 5. Reservoir geometries at the Mount Elbert Prospect, Milne Point Alaska, showing

Class 3 geometry at structural crest and Class 2 at the lateral, down-dip water contact [34].

Another example of a Type CTB accumulation characterized by Class 2 configurations also occurs in the Gulf of Mexico at the Green Canyon 955-H location. In this setting, there is a complex interlaying of gas-hydrate-bearing and water-bearing zones at the BGHS [30]. The available data suggest that the accumulation is concentrated within a relatively small fault block [31]. It appears that these faults are sufficient to segregate water and gas accumulations within the larger GC955 structure; however, it is not clear if the compartmentalization is sufficient to enable the reservoir to behave in a “confined” manner. Numerical modeling of these accumulations is now underway. Documented examples of Class 2 reservoir settings are also available for permafrost-associated settings, including the Mount Elbert (Alaska) C sand, marginal locations within the overlying D-sand (Figure 5), and several discrete zones at the Mallik well site in northwest Canada [15], including the “zone A” horizon that was the focus of the most recent test program. Initial reports on the interpretation of the 2007 and 2008 production tests at Mallik have further revealed the importance of understanding and controlling geomechanical behavior of Type C reservoirs during production [32]. Class 3 well settings: Class 3 settings describe locations where the available vertical extent of the reservoir is fully saturated with gas hydrate and delineated by bounding units of significantly reduced reservoir quality. Depressurization relies on the existence, and the ability to mobilize, free water residing within the hydrate-bearing later. Formation well testing and Combined Nuclear Resonance logging at both the Mount Elbert (Alaska) and Mallik (Canada) sites confirm mobile water saturations on order of 5-15% as well [15]. The most extensive production modeling on Type C/Class 3 reservoirs reference crestal locations of the D-unit at the Mount Elbert accumulation (Figure 5) indicate persistently low production rates that are attributed primarily to the reservoir’s low (only 2.5 ˚C) in situ temperature [33]. The situation is improved somewhat, but perhaps not sufficiently, by use of horizontal wells. Numerical modeling of similar, but warmer units documented in the western portion of the Prudhoe Bay unit have shown significantly higher production rates [6]. Similarly, recent drilling results from the Gulf

of Mexico have enabled the first numerical simulations for very warm Class 3 well locations within the Walker Ridge 313 area of the Gulf of Mexico (Figure 3). Initial models based on the “blue” and “orange” horizons resulted in estimated production rates ranging from 6 to 11 million ft3/day [25]. The gas hydrate accumulations from the Shenhu region, South China Sea, are particularly challenging gas hydrate accumulations that are somewhat difficult to classify. Data reported to date suggest a single discrete zone of elevated Sgh (up to 40% but averaging roughly 20%) that occurs near the BGHS [35]. The control on gas hydrate occurrence may be subtle increase in reservoir quality due to changes in nature and abundance of sediment grain types, including biogenic grains. If this is the case, the Shenhu deposits may be best classified as a transitional form between Type C/Class 3u and Type FPF, in which reservoir quality is just good enough to enable a pore-filling accumulation to locally high saturations, yet the permeability contrast between the “reservoir” and the bounding, gas-hydrate-barren, and more clay-rich units may be minimal. Numerical simulation of the response of the Shenhu deposit to both depressurization and thermal stimulation utilizing horizontal wells indicates that, while depressurization is clearly superior, neither method or their combination is likely to result in production rates that approach commercial feasibility [36] due to lean resource and lack of reservoir confinement. Additional examples of Type C/Class 3 reservoirs are known throughout the world. These include ash-hosted gas hydrates in the Andaman Islands [11], and various thin reservoir-quality sands reported from Korea [37], the Cascadia margin [38], and elsewhere. An intriguing case is Alaminos Canyon 21 of the northern Gulf of Mexico, where a thick and widespread sand unit has been mapped over a very large area [39]. Logging-while-drilling data from two wells drilled into this deposit suggest the unique combination of a high-porosity, high-permeability sand with low to moderate (~20%) Sgh. Confirmation of this occurrence requires further data acquisition, including coring or formation testing. Given the sheer size of this occurrence, it is unclear whether it would behave in unconfined manner to attempted production. None of these additional

examples of Class 3 reservoirs have been the subject of numerical modeling efforts, to our knowledge. Class 4 well settings: Type C/Class 4 settings describe locations where marine hydrates occur at low Sgh dispersed in unconfined coarse materials. With this new classification, the older designation of Class 4 hydrates is now covered by both Type C and Type FPF deposits, with the latter being more likely to occur in marine environments. Type F Accumulations Type F refers to gas hydrates hosted in low-permeability, fine-grained sediments. Type F occurrences are extremely widespread and the volume of methane housed within Type F reservoirs is widely assumed to be large. These sediments are typically of low mechanical strength and pose significant challenges to well-based extraction [5]. However, future engineering concepts may successfully address these issues; furthermore, the behaviour of Type F deposits may have profound implications for natural environmental change over long time-frames. To address factors most relevant to modelling the occurrence of Type F under climate change scenarios, we propose the following sub-types. Type FPF: Type FPF includes disseminated, pore-filling gas hydrate residing at low concentrations (<5%) within largely undeformed sediments of very low intrinsic permeability, typically characterized by fine silt to clay grain sizes. The Blake Ridge accumulation, offshore eastern North America, is perhaps the earliest well-documented marine gas hydrate occurrence of this type [39]. Many other similar occurrences have been noted subsequently, including the Mahanadi basin [11], and many others. Even within these systems, there remains a strong control on Sgh by sediment grain size variation [40]. Numerical simulation of FPF accumulations to assess gas production shows minimal potential using known, well-based approaches due to lean resource, low permeability, low mechanical strength, and lack of confining boundaries [8]. In the context of environmental change, those FPF deposits that occur near the landward margin of the GHSZ (pending further analysis; nominally set to where the BGHS is within 50 m of the sea-floor) are termed Type FPF-LE to denote those that

are the most susceptible to releasing methane to the oceans in response to bottom-water warming. Recently, Type FPF-LE accumulations offshore Spitsbergen Island have been described [42] and numerically modelled. These simulations indicate that gas can be liberated from these deposits at the seafloor in locations at the landward edge of gas hydrate stability over time periods on the scale of a few decades [9]. Type FGD: Type FGD includes gas hydrate deposits characterized by pervasive grain-displacing forms such as veins, lenses, and nodules. Such forms have been found widely within fine-grained sediments worldwide [43]. Two main classes are identified (Figure 6); “strata-bound” occurrences (FGD-S), and “chimney” structures (FGD-Ch).

Figure 6. Fracture-dominated gas hydrate accumulations (Type FGD) are differentiated into

“chimney” and “stratal bound” end-members based on conformance of the boundaries of the gas

hydrate accumulation with depositional strata. Within a sedimentary section, changes in lithology and sediment physical properties can result in differential mechanical response to deformation that produces fracture systems that are limited in occurrence to specific stratigraphic units. The fractures can be attractive sites for preferential gas migration and gas hydrate formation, resulting in strata-bound, fractured accumulations. Perhaps the first report of Type FGD-S accumulation was from the 2005 drilling in Keathley Canyon 151 [44] in the northern Gulf of Mexico. A much more extensive occurrence of a strata-bound fractured gas hydrate accumulation, and one that has been confirmed by multiple wells, occurs in the Walker Ridge 313 region [14]. In this area, a gas-hydrate-bearing unit roughly 500 ft in thickness

corresponded with an interval of elevated sediment density. The Gulf of Mexico FGD-S accumulations achieve only modest gas hydrates saturation, on the order of 5%, although it is not clear if this would be typical of the general type. To date, there have been no reported numerical simulations related to Type FGD-S accumulations. Type FGD-Ch deposits are characterized by numerous, primarily vertical gas hydrate veins and lenses of various scales that occur within accumulations with no apparent control by original stratigraphy, but instead appear to represent vertical focused fluid flow features. These features (“chimneys”) are typically circular in shape with diameter of 500 m or less and are typically more than twice as wide as tall. Type FGD-C accumulations have been inferred from seismic data from various locations, including offshore Norway [45], and the Krishna-Godovari basin offshore the east coast of India [11]. Perhaps the best-imaged chimney deposits are those in the Ulleung basin, Korea [46], which have also been tested via drilling and coring [12]. Chimney structures appear to commonly exhibit Sgh ranging from perhaps 20% to 40%. Given the large number of such features present within the Ulleung basin, the volume of gas contained locally in such features may be significant. However, no reports of numerical simulation of FGD-Ch accumulations, for either the purpose of evaluation of production potential or response to natural environmental change, have yet appeared. Type R Accumulations Type R refers to those rare instances where gas hydrate occurs within rocks. Examples include the Qilian Mountains of Tibet [47], Messoyahka Field, Siberia [48], and potential gas hydrates associated with the Barrow and Walakpa fields, Alaska [49]. Locally, both the Barrow and Messoyahka deposits may occur with Class 1 well settings. Neither field has been evaluated in a modern drilling program, and as such, it is anomalous production responses noted in the wells completed in the subjacent free gas zones that have enabled the gas hydrate occurrences to be inferred. However, the true nature of both accumulations remains uncertain due to inconclusive data [15]. The Tibetan occurrence includes a variety of lithologies, including sands, silts and fractured shales [47]. No numerical simulations on the Tibetan occurrences have yet been published.

Figure 7: Schematic depiction of various gas

hydrate accumulation types. Type M Accumulations Type M refers to massive forms of solid gas hydrate that occur on the sea-floor or in very shallow sediments in association with cold seeps. These occurrences are best known from the Gulf of Mexico and from the Cascadia Margin [15]. Although these seafloor mounds are occasionally discussed as possible energy production targets, the small volumes of methane volume in them, as well as their environmental significance as hosts to chemosynthetic benthic communities, would tend to preclude commercial activity. Recent studies

have sought to understand the temporal stability/dissolution of such mounds [50]. SUMMARY Gas hydrate deposits may play a significant role in future energy supply, in global carbon cycling, and in near-term environmental response to ongoing Numerical simulation will play a key role in understanding these various implications, and will increasingly treat a broader range of occurrence types. This report attempts to support future

simulation study by describing the gas hydrate occurrences in light of the most recent field results. Figure 7 summarizes these types. Type C deposits are marked by host sediment of high intrinsic permeability and correspondingly coarser grain sizes. These occurrences are most relevant with respect to energy supply potential using currently existing technologies. Type F deposits are marked by host sediment with low intrinsic permeability and typically fine grain size. Within Type F, two subtypes are recognized to differentiate pore-filling from grain-displacing modes. Type F likely represents the majority of total gas hydrate volumes, and has significant implications for environmental and geohazard issues. Consideration of Type F for energy potential may be possible provided feasible technologies are specified. Type M are those that are not sediment hosted at all, but exist as large masses, typically within very shallow sediments or physically cropping-out on the seafloor. Type M deposits have greatest significance as hosts for deepwater ecosystems. Type R deposits are unique occurrences in which gas hydrates are enclosed in rocks. They will therefore have very different mechanical response to dissociation, but will also likely be of reduced reservoir quality as compared to Type C occurrences. REFERENCES [1] Kvenvolden, K., Methane hydrate-a major reservoir of carbon in the shallow geosphere? Chem. Geol., 1988:71: 41-51. [2] Collett, T., Energy resource potential of natural gas hydrates: AAPG Bull.:2001:86(1): 1971–1992. [3] Archer, D., Buffett, B., Brovkin, V., Ocean methane hydrate as a slow tipping point in the global carbon cycle. PNAS, 2009;106(41): 20596-20601. [4] Dickens, G., Rethinking the global carbon cycle with a large, dynamic, and microbially-mediated gas hydrate capacitor: EPSL, 2002:213:169-183. [5] Moridis, G., Collett, T., Boswell, R., Kurihara, M., Reagan, M., Koh, C., Sloan, E., Toward production from gas hydrates: current status, assessment of resources, and simulation-based evaluation of technology and potential: SPEREE, 2009. October. [6] Anderson, B., Kurihara, M., White, M., Moridis, G., Wilson, S., Pooladi-Darvish, M.,

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